ALASKA STATE LEGISLATURE  HOUSE SPECIAL COMMITTEE ON OIL AND GAS  February 5, 2002 10:12 a.m. MEMBERS PRESENT Representative Scott Ogan, Chair Representative Hugh Fate, Vice Chair Representative Fred Dyson Representative Mike Chenault Representative Vic Kohring Representative Gretchen Guess MEMBERS ABSENT  Representative Reggie Joule COMMITTEE CALENDAR CONTINUATION OF ROYALTY-IN-KIND GAS SALE HEARING PREVIOUS ACTION No previous action to record WITNESS REGISTER MICHAEL HURLEY, Senior Commercialization Specialist ANS Gas Commercialization Phillips Alaska, Inc. 700 G Street Anchorage, Alaska POSITION STATEMENT: Testified that the state's proposed royalty-in-kind (RIK) gas sale, as currently envisioned, further burdens an already economically challenged project. KEN KONRAD, Senior Vice President BP Exploration (Alaska) Inc. P.O. Box 196612 900 East Benson Boulevard Anchorage, Alaska 99519-6612 POSITION STATEMENT: Expressed concerns about the state's proposed RIK gas sale as it is currently structured and about the timing. RICHARD GLENN, Vice President of Lands Arctic Slope Regional Corporation P.O. Box 129 Barrow, Alaska 99273 POSITION STATEMENT: Testified in support of the state's RIK gas sale efforts and an overland route for a gas pipeline; emphasized the need for access. DON MAHON, Vice President Alaska Power Operations Alaska Power & Telephone Company Mile 1314 Alaska Highway Tok, Alaska 99780 POSITION STATEMENT: Testified in support of the RIK gas sale. ERIC HANNAN, General Manager Power Operations Tok Area Division Alaska Power & Telephone Company Mile 1314 Alaska Highway Tok, Alaska 99780 POSITION STATEMENT: Testified in support of the RIK gas sale, specifying the benefits to the Tok region. KENNETH A. BOYD, Lobbyist for AEC Oil & Gas (USA) Inc. 23650 Sunny Glen Drive Eagle River, Alaska 99577 POSITION STATEMENT: Provided background information on Alberta Energy Company (AEC); expressed appreciation for the state's RIK gas sale; emphasized the importance of having access with certainty. ALAN SHARP, Director Northern Business Development AEC Marketing (USA) Inc. 3900, 421 - 7th Avenue S.W. Calgary, Alberta, Canada T2P 4K9 POSITION STATEMENT: Testified in support of the RIK sale and process. MARK HANLEY, Public Affairs Manager Anadarko Petroleum Corporation 3201 C Street, Suite 603 Anchorage, Alaska 99503 POSITION STATEMENT: Highlighted the added value to the state's royalty gas included in the AEC/Anadarko bid; explained the need for the state to sell its royalty gas before an open season; emphasized the need to determine FERC's authority. MARK MYERS, Director Division of Oil and Gas Department of Natural Resources (DNR) 550 West 7th Avenue, Suite 800 Anchorage, Alaska 99501-3560 POSITION STATEMENT: Discussed several aspects of the RIK sale; pointed out that it is not just a "backstopping method" but is one possible use; emphasized the need for access and for a long- term, viable gas industry. BONNIE ROBSON, Deputy Director Division of Oil and Gas Department of Natural Resources 550 West 7th Avenue, Suite 800 Anchorage, Alaska 99501-3560 POSITION STATEMENT: Pointed out that it will be easier for those who own the pipeline to expand it than for those who don't; referred to royalty-relief statutes and encouraged having the producers open their books to show whether they would be harmed by an RIK sale, which isn't shown by the state's figures. ACTION NARRATIVE TAPE 02-6, SIDE A Number 0001 CHAIR SCOTT OGAN called the House Special Committee on Oil and Gas meeting to order at 10:12 a.m. Representatives Ogan, Fate, Kohring, and Guess were present at the call to order. Representatives Dyson and Chenault arrived as the meeting was in progress. CONTINUATION OF ROYALTY-IN-KIND GAS SALE HEARING Number 0040 CHAIR OGAN announced the only order of business, the continuation of the royalty-in-kind gas sale hearing. [Alluding to the State of Alaska's Solicitation for Offers to Purchase North Slope Royalty Gas] he noted that the bidding process ended January 1 and bids were opened February 1. The four bids received were from Chevron [ChevronTexaco Corp.]; a joint venture between Anadarko Petroleum Corporation and Alberta Energy Company Ltd.; Williams; and Alaska Power & Telephone Company. He informed members that a couple of people from Chevron and Williams were listening on teleconference. Number 0211 MICHAEL HURLEY, Senior Commercialization Specialist, ANS [Alaska North Slope] Gas Commercialization, Phillips Alaska, Inc., came forward to testify as follows: Simply stated, we believe the department's proposed royalty-in-kind [RIK] sale of North Slope gas, as currently envisioned, further burdens an already economically challenged project. Let me begin by saying that we understand the state's goal to ensure third-party access to a gas pipeline. We understand that goal and the state's desire to increase the value of their unleased acreage. As the state's most active explorer, Phillips has taken a keen interest in ensuring expandability and access in a new gas pipeline. We do not, however, believe that the department's RIK backstop proposal is the most appropriate way to address those goals. Number 0297 MR. HURLEY referred to an handout labeled "Royalty in Kind Backstop Sale Example." He said it is an example of what his company understands to be the backstop proposal of the state, with the following simplified assumptions: a system that could carry 4 billion cubic feet (bcf) a day of Prudhoe Bay gas; the state, at 12.5 percent, would receive 500 million cubic feet a day; and the state would propose a royalty sale at 70 percent of that amount, which is about 350 million cubic feet a day. Number 0453 MR. HURLEY continued with his example. During the initial stages of the RIK sale, the producers' equity gas would be about 3.5 bcf a day after the state's royalty share was removed. The state wouldn't sell all of its gas, so the royalty-in-value (RIV) portion would still "be going forward" at about 150 million cubic feet a day; others would be shipping the 350 million cubic feet a day of RIK gas. The producers therefore would end up shipping about 3.65 bcf a day. In total, the system would end up with Prudhoe Bay gas at 4 bcf a day and no other gas being put into the line. Mr. Hurley told members: In looking at this, we're not opposed to the RIK sale itself. The state has the ability to take its gas and its royalty in kind, and that's not a problem. What gives us concern is the way the structure works with them flipping back to RIV after they've sold RIK. Number 0613 MR. HURLEY explained that after the sale terminates and it flips to RIV, the non-Prudhoe Bay gas would be 350 million [cubic feet] a day. The Prudhoe Bay gas would go from 4 billion [cubic feet] a day down to 3.65 [billion cubic feet], but there still would be a 4-bcf-a-day line. When the producers' gas was cut, however, the state's royalty on the Prudhoe Bay gas would go from the 500 [million cubic feet a day] it started with [at 12.5 percent royalty] down to around 456 million cubic feet a day. MR. HURLEY noted that in this kind of scenario, the producers - who are "underpinning this line" - are basically going from 3.5 bcf a day down to 3.2 bcf a day of equity gas they're trying to sell. He commented: If you think about that 300 million a day of gas times 365 times 20 years, and a buck an "M" at the wellhead, ... that's a couple of billion dollars' impact. And that is, in our view, a burden to this project. ... Now, the other option people are telling you to consider - and others would suggest - is that we overbuild the pipeline upfront, so that we could always keep the 3.5. But let me suggest to you that that in itself is a burden. ... I can spend $20 billion and have 3.5 billion [cubic feet a day] of equity gas, or I can spend $21 or $22 or whatever the number is to build a bigger line and still have 3.5 billion of equity gas. But in either case, it's a burden to the project - I've had to spend billions of dollars more. Number 0846 REPRESENTATIVE DYSON requested confirmation that to increase capacity for gas pipelines, the strategy is to raise the pressure. MR. HURLEY clarified that the end result would be an increase in compressor stations. The total allowable pressure wouldn't actually increase. REPRESENTATIVE DYSON suggested that the need isn't to build a bigger pipeline, then, but to build it with the ability to increase the throughput incrementally, as needed. He asked whether there is a mechanism by which the producers and the state can "force the folks who are adding incremental increases to the throughput" to share in the proportionate costs of increasing the throughput. MR. HURLEY said it is reasonable. He indicated the problem is not building it bigger, but that nobody's stepped up to pay for that. REPRESENTATIVE DYSON requested confirmation that it wouldn't be bigger, but thicker. MR. HURLEY answered in the affirmative, indicating it would involve putting more compressor stations along the line, including [changes in] siting and design - whatever it takes to get more throughput. He added that the system would be built to be expandable. Number 1005 REPRESENTATIVE DYSON asked whether the producers, because they would finance the first increments and would have to build the original design to accommodate future expansion, would want "guys with a big checkbook to help in that." MR. HURLEY replied, "I think that's reasonable if they want expanded capacity." REPRESENTATIVE DYSON mentioned the state's responsibility to get its own royalty share to market and maybe a larger responsibility to make sure other gas fields in the area get developed and commercialized. He asked whether Mr. Hurley was saying the state needs to determine how to ensure that everybody pays a fair share, or to help the producers determine it or put the tools in place. MR. HURLEY said that is correct. Number 1102 REPRESENTATIVE DYSON inquired about the open season. He alluded to previous testimony, mentioning that after the open season a company is in a less advantageous bargaining position to get a reserved place in the pipe for its gas. MR. HURLEY answered that one can propose an expansion at any point. With expansion comes additional open-season opportunities because it is governed by the same open-access requirements for the original open season as far as nondiscriminatory access. REPRESENTATIVE DYSON replied that he has heard a different perspective, however. He then mentioned two alternatives: ensuring that this transportation route for gas is like a common carrier or doing it in a way that isn't detrimental to those who took the risk to build and finance it in the first place; he suggested "either end of the problem" could be worked. Number 1294 MR. HURLEY returned to his presentation, emphasizing that the RIK backstop proposal "will decrease revenues to us" and increase the level of uncertainty for the project. He added, "We have a hard time envisioning how to move forward on the project with this kind of situation unchallenged, where we can end up getting arbitrarily cut back or being forced to pay for additional capacity upfront." He closed with the following remarks: We share the state's desire for equitable pipeline access. We're committed to fair and open access to any gas pipeline in which we participate, consistent with the regulatory requirements and direction of the Federal Energy Regulatory Commission [FERC]. They have a regulatory structure in place which requires open, nondiscriminatory access for both initial and expansion volumes. And we believe their regulatory oversight will ensure, as it does throughout the U.S., that all potential shippers are treated fairly and that economic burdens are distributed equitably. We encourage you to look carefully ..., as you consider this proposal, at the impacts it has on the economics of the other potential shippers whose long- term shipping commitments will underpin the financing of this project. Number 1407 CHAIR OGAN pointed out that some don't share the viewpoint that FERC will regulate this as fairly as Mr. Hurley said, because of the belief that FERC's power is a little more limited regarding the regulation of open seasons than how the producers characterize it; Chair Ogan said he would like to have that verified [by an expert on FERC]. CHAIR OGAN referred to testimony that this would be not a common-carrier pipeline but a contract pipeline. He suggested it would be in the state's best interest to encourage smaller, independent companies to come to Alaska to do business. He asked Mr. Hurley what he thinks. MR. HURLEY answered that FERC regulates the gas pipeline business throughout the U.S. There is a longstanding regulatory structure in place; it regulates access both for initial open seasons and expansions. He noted that the initial open season happens before [a company] even files an application for a certificate; it is subject to FERC review and to challenge by any people who feel they have been treated unfairly. CHAIR OGAN requested confirmation that someone who finds gas later couldn't make the producers or anyone else add gas into a contract pipeline. MR. HURLEY affirmed that there is no provision for FERC to force an expansion. He suggested, however, that it isn't desirable to have a regulatory body, which is subject to political pressure, forcing people to do things in the economy. Number 1560 CHAIR OGAN proposed that how much gas can be produced is based upon how economic it is to draw down from the existing fields, including the effect on oil production. Referring to the Fairbanks meeting in 2001 of the Joint Committee on Natural Gas Pipelines, he said the Alaska Oil and Gas Conservation Commission (AOGCC) testified it was looking at that and revising the models because previous assumptions were based on 2.5 bcf [a day]; it was uncertain what an approximately 4.5 [bcf a day] drawdown would do to [oil] production. CHAIR OGAN asked how much that factors into [the producers'] decision regarding how much gas to produce from the existing fields. He added that it isn't an issue at Point Thomson, for example; gas in the foothills and gas that independents are producing, however, might ultimately affect the amount of oil produced. He asked how much that drives [Phillips'] decision regarding how much gas will go through the line. MR. HURLEY responded that it is a hard question to answer, but many things come into play regarding the initial design rate. Those include oil losses, market estimates, and technology. For example, it would be a technological challenge to build a system big enough for all the gas that Prudhoe Bay could produce instantaneously, "8 bcf a day or whatever it is we're currently recycling." Number 1705 CHAIR OGAN asked Mr. Hurley whether he has studies regarding the relationship between drawdown of gas and [oil] production. He indicated he'd like to see such a study from the AOGCC. He offered his understanding that the producer group hasn't agreed to fund a study with the AOGCC and mentioned possible funds there to do that. MR. HURLEY replied that he was "at a loss" about the funding of the AOGCC to do that. He added: I know they have been looking at some models, as we have internally. All the companies have got reservoir models of Prudhoe and are looking at what the potential is for oil losses based on mitigation measures, based on when gas sales start and the volume that gas sales begin at. All of those things have an impact on oil losses, and it's a relatively complex model to try and do that. Number 1783 CHAIR OGAN expressed his understanding that there was a meeting set up between the producers and AOGCC. He asked, "How much of that information are you willing to share with them?" He suggested that [Phillips'] showing the AOGCC its model might help the AOGCC with an independent analysis. He pointed out that legislators aren't petroleum engineers and must rely on others for information. He offered his belief that it is a "driving factor" in this whole issue. MR. HURLEY agreed it is an important factor, but said he isn't aware of the status of those discussions with the AOGCC and couldn't comment on how they were going. He added, "Our reservoir folks have been talking to the AOGCC off and on." CHAIR OGAN requested that Mr. Hurley pass on to Phillips' managers that Chair Ogan would appreciate as much cooperation as possible. MR. HURLEY agreed to that. CHAIR OGAN asked whether there were further questions, then thanked Mr. Hurley for his testimony. Number 1870 KEN KONRAD, Senior Vice President, BP Exploration (Alaska) Inc., testified via teleconference, noting that he is the vice president in charge of BP's gas interests in Alaska. He told members BP supports the following: the state's right to take gas in kind; "exploring for new sources of gas that could be produced into a gas pipeline"; and expansion of gas pipeline capacity on open, fair, and reasonable terms. He stated: BP, ... Phillips, and Exxon are in the process of completing ... a major feasibility and engineering study on a possible gas pipeline. An essential premise in that study is designing a pipeline system that can be easily expanded, and we have been successful in achieving a design that has higher expansion capability at lower cost than any other proposal that we've seen. We firmly believe that efficient pipeline expansion can benefit both existing producers and explorers as well as ... the State of Alaska. We understand the state's desire to see additional development of additional gas beyond the existing known resource. Indeed, the feasibility study we have undertaken this year assumes that additional gas will be found beyond the 35 trillion cubic feet [tcf] of currently known gas. We currently assume at least 50 trillion cubic feet of total gas will be needed during the project life. Separately, BP is working on a major study with the Department of Energy and the University of Alaska Fairbanks to study a possible way to produce the enormous gas hydrate resource known to exist in and around existing North Slope fields. This resource alone has been estimated at nearly 50 trillion cubic feet. This is really a long-term possibility with many technical challenges, but it's indicative of our active support for new sources of gas supply. We certainly support the state's right to take gas in kind. This is clearly a choice ... the state should make on its own. Our sole request is that the state do so in a predictable manner that is consistent with how a "contract-carry" gas pipeline would operate. So we fully support the state's ability to take in kind, we fully support pipeline expansion on fair and reasonable terms, and we fully support finding new sources of gas supply. And it's in our best interests ... for all those things to occur. Number 2030 MR. KONRAD continued: We do, however, have concerns over the proposed state sale of "take-in-kind" gas as currently structured, and also with respect to timing. We've openly discussed our concerns with DNR [Department of Natural Resources] over the past several months. The state has frequently indicated that this proposed RIK sale is being driven by the perception that the Alaska Gas Producers Pipeline Team may hold an open season for pipeline capacity in early 2002. We do not foresee any possibility of holding an open season anytime during 2002. As we've talked about previously, for a gas pipeline to attract investment there first needs to be an economic project. And further, to reduce project risk, there also needs to be a predictable and viable government framework in place to support that investment. Both federal regulatory legislation and clarity around fiscal terms are important pieces of this government framework, and to date, neither of those vital ingredients is currently in place. According to the DNR, the state's proposed RIK sale is being pursued primarily to provide a capacity-access option to explorers without currently proven gas resources, the idea being that the explorers could use the state's RIK gas to backstop their own bids for [firm] transport capacity on the new-build line, and then release that RIK gas back to the state, should they find their own reserves. The ability of RIK purchasers to return gas to the state on a relatively short notice period places a significant additional burden on our overall project economics by increasing the uncertainty on the amount of equity gas the major producers would be able to ship. That translated means uncertain cash flow. This burden on an already marginal project is a clear step in the wrong direction. Number 2147 MR. KONRAD offered an example similar to Mr. Hurley's: a pipeline designed to transport 4 bcf a day, with the state taking one-eighth in kind - 500 million cubic feet a day. An RIK purchaser could use its purchased gas as a backstop for making a long-term firm transportation (FT) commitment on a gas line; the balance of the commitments to get the line built would need to be made by the known resource owners. If an RIK purchaser discovered its own resources, however, it could cancel its purchase contract with the state and substitute its own gas into its firm transportation commitment. The state's gas would then revert back to the known resource owners in the form of RIV, thus reducing throughput by 500 million cubic feet a day, "reducing our own gas production that the resource owners had already made financial commitments for." MR. KONRAD advised the committee that this reduction in cash flow against the binding financial commitment is clearly negative from an investment point of view. The state's RIK proposal seeks to transfer benefits from long-term investors to new participants without transferring the risk, he said. Those subsidies are at the expense of those who ultimately will underwrite any new-build pipeline. That is unfair. More important, from the state's perspective, it will reduce the chances of developing an economically viable project. He pointed out that obviously there is no access to a pipeline that never gets built. Number 2237 MR. KONRAD summarized his earlier points: BP firmly supports the state's right to take gas kind. We support pipeline expansion on fair and reasonable terms. And we support vibrant exploration for gas. We believe FERC will ensure fair and open access to any gas pipeline. And in any event, it's in our best interests. However, we cannot at this time support the ... state's proposed RIK sale as it's currently structured. We're deeply concerned, if the state tries to fix this perceived problem with economically burdened solutions, that that cannot possibly be in the best interests of the state. Number 2270 CHAIR OGAN referred to earlier discussion regarding [gas] drawdown and its effect on pipeline throughput and the oil companies. He then referred to an e-mail from Cammy [Oechsli Taylor] of the AOGCC; he noted that it offered the understanding that the funding for the reservoir study was coming from the gas line appropriation to DNR, but that the companies have not yet covered those costs. He asked whether that is accurate, to Mr. Konrad's knowledge, and whether "you guys are willing to step up to the plate with that." He requested clarification about the funding. MR. KONRAD said he wasn't aware of a funding issue. He expanded on his answer: The Prudhoe owners have met on a few occasions with the AOGCC, and I know their work is continuing kind of on a parallel path with our work. ... We're set to be finished up with our study the end of February, and I'm not sure exactly what the exact status of the subsurface work is, but I do know that there was an intent ... to share results of ... that work with the AOGCC and have a discussion. But I don't really know exactly where it sits. We certainly factor that into the equation as we look at it. I would just point out that certainly the producers are quite aligned with the state in the regard of oil losses. It is, clearly, a potential burden to the project if you produce less oil, and that's why we're looking at mitigation measures and investments to help reduce that. But nevertheless it is there and present. But, clearly, we're aligned with the notion of maximizing the total value of the resource, so that's inherent in our analysis. But I haven't seen any final work out of the Prudhoe group, but I would imagine ... they'll be finishing their phase of work here in the not-too-distant future. Number 2410 CHAIR OGAN agreed it is one area where the producers and the state are aligned; all will lose revenues if there isn't as much oil. He asked that Mr. Konrad pass along to BP's manager the same request asked of Phillips, that Chair Ogan would appreciate as much cooperation as possible. He acknowledged that much information is proprietary, but emphasized that the more information the AOGCC can have, the more independent an evaluation the legislature can have, and the easier it will be to make a decision. MR. KONRAD responded that he hadn't heard from [Ms. Oechsli Taylor] in a while, but said he would contact her to check on that. He would also check with "our Prudhoe folks." CHAIR OGAN asked whether there were any questions; none were offered. He requested that Mr. Konrad fax his written testimony, if available. Number 2492 RICHARD GLENN, Vice President of Lands, Arctic Slope Regional Corporation (ASRC), testified via teleconference. Noting that he had e-mailed several pages of written testimony, he offered to summarize. He informed members that ASRC, which represents more than 8,000 Inupiat Eskimos in northern Alaska, owns surface and subsurface title to more than 4 million acres of North Slope lands; by virtue of that ownership, he said, "we represent the largest private landowner on the North Slope." He noted that ASRC has millions of acres of "high-value resource potential" lands in the central Arctic foothills. Therefore, he said, "We believe that our interests are closely allied with the state with respect to natural gas from the central Arctic." MR. GLENN spoke in support of the state's royalty-in-kind gas sale efforts. He explained that without such a program, ASRC believes there is a potential for a "foreclosure of the resource potential" of the central Arctic lands. He said ASRC recognizes that the gas resources at Prudhoe Bay, Point Thomson, and the surrounding fields are what began this discussion. He told members: For us, it's kind of a mixed blessing. It's a huge resource potential. It needs to be recognized, and we do recognize that. ... We are partners with the oil industry. We have a future with them, and we don't want to spoil that. We recognize that, and we want to continue [a] productive working relationship. Yet we recognize that we have to speak up for our interests. And we do not wish to shut off the exploration and development of additional North Slope natural gas reserves. In addition to achieving the larger goal of getting to the nation and helping the state with its revenue derived from resource wealth, we ... speak to protect the economic interests of our people, and that economic interest centers around access. Number 2654 MR. GLENN continued: We want access to capacity. In addition to that, we require access to opportunity and to the planning process of a North Slope natural gas line. We strongly encourage the Alaska legislature to make every reasonable effort to ensure access to future gas owners on a North Slope natural gas pipeline. We know that one way to do this is through the royalty-in-kind gas sale. This can act as a backstop for future access into the gas pipeline. ASRC feels that the royalty-in-kind sale is a necessary placeholder to maintain pipeline capacity for nongas owners. This access to natural gas pipeline capacity is critical. If we cannot be assured of reasonable access to space on a pipeline, then our industry partners in the central Arctic will not explore for or develop natural gas outside of the Prudhoe Bay, Point Thomson, and related fields. And in doing so, this would, in effect, condemn more than 11 million acres of highly prospective Native- and state-owned lands to future exploration potential for many years to come. But in addition ... to pipeline capacity, we think that there are other things that the state should be cautious about. We know, for example, that the Prudhoe Bay gas is enriched, for example, in carbon dioxide, CO2. And we fear that if secondary services of gas processing are bundled together, ... any other gas found outside the Prudhoe Bay area that, for example, is not enriched in CO2 might be burdened with this gas-treatment cost. Number 2734 MR. GLENN urged the legislature to consider researching whether unbundling secondary services such as gas conditioning would allow a fair tariff structure to be set. He explained that all gas that leaves the North Slope will require processing in some fashion; every field has a different chemistry and a different pressure, so the processing for each field is different. He explained: We just do not want fields that do not need additional processing to be burdened with that cost. As you know, with centralized facilities and a single pipeline leaving the North Slope there's going to be sharing of these facilities, and we urge the legislature to assure that there's a fair sharing of these facilities. ... The current producers need to be recognized and compensated for their investment. On the other hand, we don't ... want to see excessive charging ... resulting in an unfair tariff structure. Number 2792 MR. GLENN outlined ASRC's concerns regarding the current producers. First, the current producers may attempt to include excessive capacity "holdbacks" - setting aside more pipeline capacity than necessary for their own internal purposes. Second, they have the opportunity to make transportation capacity on the pipeline either completely unavailable or unreasonably expensive to shippers who aren't able to secure firm capacity under the initial open-season process. Finally, they can force new shippers to sell their "stranded gas at distressed prices to those who are controlling the transportation." A further possibility is that the producers may forestall or delay expansions that would provide additional capacity. He told listeners: These are things we are worried about. It's not just a matter of how much gas can fit in the pipe, but it's how all of this capacity and gas processing is going to be monitored and regulated. We don't want to see it regulated out of business. We don't want to see an overburdened pipeline project. On the other hand, we need the access. Number 2884 MR. GLENN noted that his written testimony, which discusses access to opportunity regarding pipeline construction, was provided to the governor's [Alaska] Highway Natural Gas Policy Council. Pointing out that it also discusses access to the process, he emphasized that ASRC, as "a neighbor and a resource owner," wishes to be at the table when decisions are made regarding the gas pipeline, including ownership, construction, and operation. MR. GLENN spoke in support of having an overland route for the gas pipeline, saying it would benefit all Alaskans. He encouraged the committee to review "all the issues, and not just the interests of a few gas owners," to better understand the impacts of North Slope Alaskan natural gas development. He concluded by saying, "We believe that the State of Alaska and the North Slope Inupiat people have much in common with respect to natural gas, and we can work together to protect the interests of all Alaskans." Number 2903 CHAIR OGAN expressed appreciation for Mr. Glenn's testimony. He added, "I don't think it's a secret around here that we share your concerns about a northern route and are working to try to get that line to go south, for a number of reasons." He asked if there were questions; none were offered. Assuring Mr. Glenn that the committee was giving it full attention, he noted that the legislature must decide whether to approve the RIK gas sale. TAPE 02-6, SIDE B Number 2924 DON MAHON, Vice President, Alaska Power Operations, Alaska Power Company & Telephone Company, testified via teleconference as follows: Alaska Power [& Telephone] Company has been providing regulated electric services to several rural villages along the route of the proposed natural gas line. Alaska Power [& Telephone] Company has been issued a Certificate of Public Convenience and Necessity by the Regulatory Commission of Alaska [RCA]. ... Under the terms of our certificate we are obligated to provide safe, affordable electric energy, free from unreasonable interruption. Pursuant to this, we have investigated the potential savings to our rural customers by converting our existing diesel power plants to use natural gas as fuel. Natural gas provides many advantages over alternative fuel sources. It is easy to use, clean-burning, and cost-effective. Natural gas is increasingly a fuel of choice in areas where it is available. According to the 2000 Supplemental Census, natural gas is the number-one choice for home heating, with 70 percent of new homes completed in 2000 equipped with natural gas. According to the Department of Energy's Representative Energy Costs for 2001, natural gas is a highly cost- effective energy source as compared to alternatives. All review thus far shows that fuel-cost savings are sufficient to cover the investment and create a significant economic benefit to the residents of the area. Another economic benefit would be realized by the State of Alaska in that the power cost equalization received by the community would be reduced. Further, we determined that purchasing of royalty gas directly from the State of Alaska enhances the economic benefit and increases the likelihood that the project [would be able to secure] a tap on the mainline and offers some standing when having discussion with the pipeline company and regulatory agencies. MR. MAHON noted that after Mr. Hannan discussed the benefits to Tok and the surrounding area, he himself would provide a conclusion. Number 2804 ERIC HANNAN, General Manager, Power Operations, Tok Area Division, Alaska Power & Telephone Company, testified via teleconference as follows: Our intention is to demonstrate a real demand for local use in Alaska as well as the business [proposition] for fulfilling that demand. We chose to look specifically at [the] economics of placing such a service here in Tok. We currently serve our communities with both power and telecommunications. The first business enterprise we examined was a natural gas local-distribution company, which will tap into the trans-Alaska natural gas pipeline and distribute the gas to our [residential], commercial, and industrial customers. We have also studied using natural gas in the production of electricity. Currently, we burn diesel fuel to generate electricity in Tok. The presence of natural gas in the area would provide an opportunity for [Alaska Power & Telephone Company] to switch over to the more efficient, environmentally responsible natural-gas-driven generators. This will also pave the road for new forms of electrical generation, i.e., microturbines, fuel cells, and whatever new technology has in store for us in the future. [Mr. Hannan's testimony cut out briefly, but his written testimony said the result would be that cost savings would be passed back to the consumers and the state in the form of lower electric rates]. The cost of gas is a critical variable to the success of both proposals. If we assume a wellhead price of gas of $1.00 per Mcf plus transportation costs of $.80 to $.90, the FOB cost would be $1.90 Mcf less the cost of tap and removal of liquids. If we assume all-in costs of $2.56 Mcf, the cost per mmBtu is $2.56. The cost of diesel fuel [at $1.00 a] gallon is ... $7.25 per mmBtu - significant savings to our customers of approximately $294 per annum per customer. The key element, of which we must remain cognitive, is the cost and affordability of the gas. Number 2712 MR. MAHON concluded his company's testimony as follows: It is crucial that FERC does not limit the RCA's ability to set tariffs and conditions that will allow in-state gas purchases to be affordable for Alaskans. Development of an affordable natural gas infrastructure is vital for future economic development. An excellent example of future development along the path of the pipeline is the mining industry. We must make every effort to keep the costs of all future development feasible. Alaska Power & Telephone is in full support of the royalty- in-kind gas sale. Number 2680 CHAIR OGAN referred to discussion during the interim, in the Joint Committee on Natural Gas Pipelines, about the issue of RCA's having a place at the table. He remarked: We've looked at a number of ways to try to keep FERC out of it for the intrastate gas use and, quite honestly, haven't been able to come up with a way to do it. And I was looking at maybe trying to statutorily move the wellhead down to a hub concept or something to keep in-state regulation to a point where people can hook up and FERC regulates it from there out. And all the feedback we've gotten from the "legal beagles" is that ... if one molecule of gas goes to the Lower 48, FERC regulates the whole thing. I think maybe the best approach that we can hope for is that ... RCA and FERC [allow] kind of a joint committee. ... That might be something we want to request in the enabling legislation with the feds, is some kind of a joint RCA-FERC committee or subcommittee that regulates this particular gas line so Alaska has a place at the table. So, being one that doesn't like the feds regulating things, I think it might be a good way to represent our interests. ... We're aware of it and we're working the issue, and hopefully we can resolve it. Number 2601 CHAIR OGAN requested that Mr. Mahon and Mr. Hannan forward their written testimony to the committee aide. Number 2582 REPRESENTATIVE DYSON asked whether it is reasonably easy to convert existing diesel-fired generators to operate on natural gas, and whether Alaska Power & Telephone Company would be able to do so with its machines. MR. MAHON answered, "That is true, and we'd be able to do that with our machines. Also, we'd have to take into consideration the conversion cost versus purchasing new machines." CHAIR OGAN wished the testifiers good luck with the bid. He then called upon testifiers from Alberta Energy Company (AEC). Number 2502 KENNETH A. BOYD, Lobbyist for AEC Oil & Gas (USA) Inc., came forward to provide background information. He informed listeners that AEC first came to the state a few years ago when he himself was director of the Division of Oil and Gas. After hearing what AEC proposed to do - to buy leases in the foothills to develop gas, when there was no gas pipeline, and to work on a offshore [oil] prospect called McCovey with Phillips and Chevron - he'd commented in a newspaper that AEC had "jumped into the deep end of the pool." Mr. Boyd remarked, "Indeed, they continue to be in relatively deep water. You're the lifeguard. I'm trying to help." MR. BOYD noted that the previous year Phillips decided not to go forward as operator of the McCovey oil prospect; located about 11 miles north of Prudhoe Bay in the Beaufort Sea, it has all the problems of offshore development, but also the potential benefits to the future of the State of Alaska. He reported that AEC is bringing a new technology to the table, has worked well with state and federal agencies, and is "working very carefully and hard" with Native organizations to give them some assurance that there will be a safe operation. Number 2433 MR. BOYD turned attention to gas. He expressed appreciation for the state's providing the RIK program, citing the importance of having access to the pipeline with certainty. Noting the high risk, he told members [AEC] and its partner Anadarko are working in the foothills, where they've bought leases and shot seismic [data] for two years, making "substantial investments in a new place for them." Mr. Boyd pointed out how different the rules are from Canada's and how many agencies one must go through here. Referring to AEC, he said, "I think you're looking at the future of Alaska; I think these are going to be very important players in our future." He then introduced Alan Sharp, who would talk about the RIK program. Number 2370 ALAN SHARP, Director, Northern Business Development, AEC Marketing (USA) Inc., informed members that he was testifying in support of the royalty-in-kind sale and process. He offered four key points from a handout titled "Royalty In Kind (RIK) Sale." First, RIK is in the state best's interest. Second, it must be done now while there is a window of opportunity. Third, it won't impact the producers or the Alaska Gas Producers Pipeline Team. And fourth and more important, he said: We're coming at it from an explorer's perspective. What we're trying to offer here is not just a royalty- in-kind bid. What we're trying to offer is the state to share in our vision of what we see for the natural gas industry in Alaska. We want to see a competitive, multiplayer natural gas industry in Alaska, and we [believe] that the royalty-in-kind sale is the first step towards making that happen. Number 2313 MR. SHARP brought attention to page 2 of the handout, a map labeled "AEC Alaska Project" that shows the North Slope and current natural-gas proven reserves, with 25 trillion cubic feet at Prudhoe Bay and 5 trillion cubic feet at Point Thomson. The breakdown shows that the majority of proven reserves are held by three companies: BP, Exxon, and Phillips [BP Exploration (Alaska) Inc., ExxonMobil Production Company, and Phillips Alaska, Inc.]. He pointed out that those same three companies comprise the Alaska Gas Producers Pipeline Team. MR. SHARP advised the committee that AEC and Anadarko are exploring in the foothills region just for natural gas. The gas found thus far in Alaska predominantly has been found by exploring for oil. The potential in the foothills where AEC and Anadarko are exploring is 26 trillion cubic feet, whereas the ultimate potential for the North Slope is 100 trillion cubic feet. He told listeners, "We want to make sure that the pipeline is designed properly right from the start so it takes into account the full potential that's here in Alaska." Number 2257 MR. SHARP addressed some of the reasons RIK is in the state's best interest [page 3 of the handout]. Noting that there is no risk to the state as the bid is being proposed, he explained: The state is actually leveraging its gas volumes of tomorrow to support exploration projects of today. Those exploration projects represent in-state expenditures for exploration, more jobs, more revenue coming into the state, and essentially creates a competitive gas industry. The way that the royalty-in-kind sale maximizes the state's values through this competitive bid, you've got four bids in front of you, and everyone's put forward their best competitive bid. And I think the other thing that's important to note in our bid is that we've guaranteed that the royalty- in-kind price will be greater than the royalty in value. So there is no risk from a monetary perspective. In fact, the state's better off to accept a royalty-in-kind bid versus just the status quo, leaving it royalty in value. Number 2202 MR. SHARP discussed why RIK is needed now [page 4]. The timing is critical with regard to the window of opportunity. The RIK sale takes five months to carry out, plus there must be legislative approval that [normally] only occurs between January and May. If an open season falls outside that window, the opportunity is lost. Mr. Sharp noted that the "producer team" has just said "they do not foresee an open season being held in 2002." He pointed out that if an open season were held early in 2003 with no notice, the opportunity still would be lost. MR. SHARP advised members that AEC recommends the following: an open season June 2003 or later; at least six months' advance notice; and, more important, complete disclosure of the [tariff] terms and conditions, especially regarding access and expansion. He suggested that if the pipeline is designed correctly from the start, it can be designed "with smaller increments that support exploration and more players and more competition and essentially more jobs and dollars" coming into Alaska. He proposed increments of perhaps 200 million to 300 million cubic feet a day, from a 4-bcf-a-day pipeline to, say, a 5-bcf-a-day pipeline. Number 2127 REPRESENTATIVE DYSON noted that if it is required that the initial pipeline construction facilitate incremental expansion, he'd heard the producer group say there is a cost to it. He asked who should bear that cost. MR. SHARP offered his personal view, from his understanding of how pipelines are being built, that if it's designed in right from the start, there would be little or no incremental cost in order to have that expansion in increments of 200 million to 300 million [cubic feet] a day. As mentioned earlier, it's just a matter of "putting in a compressor and the proper spacing." He proposed that if that has been anticipated in the design, it should be quite easy to do, at little cost. He added, "I think if there was incremental cost, ... that's where we'd sit down and talk about it." Mr. Sharp said the "explorers" would like access and the ability to communicate their concerns and issues regarding how the pipeline is being designed. Number 2060 REPRESENTATIVE DYSON asked whether there is a role for legislators to play to help make sure that conversation happens so that potential users get access but the producers don't get saddled with costs and time delays that would "impact the survivability and economics" of the project. MR. SHARP answered that first, there should be a joint meeting among the producers, the explorers, and the state. Up to this point, that hasn't happened. He said he views the RIK sale as a process of helping to facilitate those discussions and negotiations. Noting that [page 7] of the handout relates to FERC, he countered the view of the producer team that FERC can support or mandate that process. Number 1962 MR. SHARP, in response to a comment from Representative Dyson regarding the open season, indicated AEC has a different interpretation from that offered by the producer team. He added: We're making investments in the state right now. We're exploring for gas. We want to make sure that we can "monetize" that gas economically. And it's basically the same thing that the producers are saying too. They'd like to lower their risks and their costs; they need certainty. And I think that's what we're looking at from a royalty-in-kind-sale process. It provides us that certainty. And we do not believe it's a detriment to the producer group. Number 1931 REPRESENTATIVE DYSON responded that he'd understood [the producer group] to say it's not a problem and that someone can always get in and ship the product if willing to participate in an incremental cost increase. Therefore, the desire to get a reserved place during the open season is largely an academic problem. Number 1907 CHAIR OGAN recalled that there was a lot of discussion about that in the Joint Committee on Natural Gas Pipelines. He offered his understanding that once the open season is closed "it's pretty much closed." He added, "I don't think FERC can make them do it." It's a big issue, he said, and whether there is further exploration by independent companies in Alaska is what this hearing, and this whole issue, is about. He said DNR is trying to facilitate the independents and some competition. CHAIR OGAN emphasized the need to hear from a "FERC attorney." Although some independents have such legal counsel on staff, Chair Ogan said he didn't know whether that was true of AEC. That is the debate here, he pointed out. There is a difference of opinion. REPRESENTATIVE DYSON agreed that the committee needs to know whether FERC has jurisdiction and what it can do. In addition, members need to know about the ability to buy capacity after the open season, and at what cost. Because of the different opinions, he suggested the need for a process that leads to a conclusion that members can have confidence in. Number 1808 CHAIR OGAN announced that he planned to appoint a subcommittee to study this issue and perhaps facilitate discussion between the producers and independents, if all are willing to come to the table. Number 1785 MR. SHARP addressed Representative Dyson's question as follows: I think the explorers' concerns are, first, in the open season. The open season's going to be structured by the parties that initiate it. It's not FERC- regulated. ... Our concern is that we can't make a commitment during that initial open season without proven reserves. We need some other type of backstop or what I would refer to as an insurance policy, which the royalty-in-kind offers. And then the problem with waiting for an expansion is - if you haven't designed the explorers' interests, of that incremental capacity, in right from the start - the expansion could be structured so that it's very onerous to those that want to actually expand the pipe. So it may not be economic for that party seeking the next expansion. Or it could be designed in such a manner that instead of going from just 4 [bcf a day] in increments of 2[00 million] to 300 million a day up to 5 bcf a day, you have to actually do the expansion in one large, incremental step of 1 bcf a day. That would exclude a lot of new entrants from a pipeline. ... What we'd like to see is a competitive, multiplayer industry. I think it's in the benefit of everybody to have more players generating more jobs and more revenue for the state. And I think the way to do that is to ensure that the expansion is done in an appropriate manner that supports the new entrants to the pipeline. Number 1713 CHAIR OGAN noted that during the open season, AEC wouldn't have gas but would be looking for it, in a joint venture with Anadarko. If the season closed and if FERC could not, by regulation, allow entrants after they find gas, "then basically you're done looking up there." MR. SHARP suggested other new explorers would be done looking too. There would be 20 years when the pipeline would be full, during which time the existing shippers on the pipeline would start exploring to keep that pipeline full. With a potential of 100 trillion cubic feet on the North Slope, he said, "I guess what we're hoping is that you would allow explorers like ourselves - and other explorers - to be able to take advantage of that potential as well, not just the three parties that are there right now." Number 1641 MR. SHARP referred to page 5, "Explorers' Pipeline Decision Timeline." He indicated [between 2005 and 2006] is the earliest date for the explorers on the foothills project and the North Slope for gas, and that AEC and Anadarko are the furthest along in this regard. Even if the open season were delayed until 2003 or 2004, Mr. Sharp said, they would be in the same situation. "So we need something else such as a royalty-in-kind process to participate in that initial open season," he concluded. Number 1608 MR. SHARP turned attention to page 6, labeled "State's Royalty in-Kind Decision Timeline." He noted that it highlights, from the state's perspective on the RIK sale, the reason for having it now. He pointed out the window of opportunity shown on the chart for the state's process of a RIK sale, as well as an example of a timeline for an open season for the Alaska Gas Producers Pipeline Team. He emphasized that if there is no commitment from the producer pipeline team, the open season could occur anytime, perhaps outside the window of the RIK sale. Number 1563 MR. SHARP returned attention to page 7, regarding how FERC can help; he noted that this is where there is disagreement with the producer group. He referred to the first four "bullet points," which read [with punctuation changes]: Can not force a pipeline expansion Open seasons are encouraged but not required Open seasons are not regulated (complaints basis) Open seasons filed significantly before the application - helps determine design and size of pipeline required for application MR. SHARP noted that these comments were from the testimony of Robert Cupina, FERC's Director of Energy Projects, on July 17, 2001, in a Joint Natural Gas Pipeline Committee hearing. Mr. Sharp further noted that there is a "case precedent, legal precedent, Section 7 of the natural gas Act and Panhandle Eastern, which supports our views here." Basically, he said, FERC cannot force an expansion of the pipeline. Open seasons aren't regulated or required; if his company had a problem with the open season from an explorer perspective, it would have to be under a complaints process, which is inefficient, expensive, [time-consuming], and usually "doesn't result in a reasonable outcome." MR. SHARP discussed a second key point. An open season is held significantly ahead of time, before an application; the reason is that it is used to help design and size the pipeline. Because there is a difference of opinion regarding FERC's power in this regard, he proposed that access and expansion terms be written into "the producers' federal enabling legislation." That would clarify all the rules for access and expansion for everyone. Number 1472 MR. SHARP noted that pages 8 and 9 talk about, from the explorers' perspective, how they will use the RIK sale. He explained: Essentially, what we're faced with is exploring and wanting to monetize natural gas in Alaska. However, in order to do that, we need firm service. The firm service is an obligation of $150 million a year. And over a 15-year timeframe, it's over $2 billion. And if the term of the firm service is 25 years, it would be over $3 billion dollars. Now, without proven reserves - as explorers - we just can't commit to that type of financial commitment. And that's where we come in with the royalty-in-kind proposal. MR. SHARP discussed a section of page 8 that read: State RIK backstop agreement - acts like insurance policy for Explorer - not a handout, Explorer competing and paying for RIK gas - State receives RIK price [greater than or equal to] RIV price MR. SHARP explained that the state would be backstopping the firm service, while [the explorers] would pay a premium relative to [the state's] royalty-in-value gas price that it would receive in royalty-in-kind gas. He emphasized that the explorers aren't asking for a handout, but would be paying a premium for the right to have this type of insurance policy. "We're guaranteeing that the royalty-in-kind price will be greater than the royalty-in-value," he added. Number 1379 MR. SHARP referred to page 9, noting that it shows the timeline of the firm service versus the royalty-in-kind purchase agreement. He told members: We will know by 2005 whether our exploration is successful on the foothills. And by 2007, which you can see in our bid document, that's when we will have ensured that we've met ... our work commitment on the North Slope; otherwise, we'd pay liquidated damages. So we'll actually know, before the pipeline even flows, whether we're successful in our exploration and we'll have our own gas to flow or that we require the backstop. And I think because of that, then, the producer group has more than advance notice of what our plans will be. And we would like to work together on how that would work, with the state as well as the producer group. Number 1340 MR. SHARP turned attention to page 10, "Foothills Gas Decision Tree," which relates to decisions regarding development. First is ["RIK bid success"], which is happening now; second is the open season, during which "we would have to commit to firm service and the onerous liability of the firm service demand charges"; and third is "exploration success." He pointed out that the state receives a benefit in all cases, without risk. He characterized it as a win-win situation for everyone. MR. SHARP elaborated. Even if there were no bid, he said, "the state knows what the value of your gas is because you have four bids coming in, and it gives you an idea of the interests and the ideas that you could have for monetizing your gas." As for the pipeline firm service, he said, "If we're unsuccessful in the open season for some reason, you'd still have our [exploration work]." He added, "In the foothills, you know what the potential is for gas, on the foothills and the North Slope." MR. SHARP told members that if the company were unsuccessful regarding exploration, "we would be mitigating the transportation charges that we have under the royalty-in-kind sale, and over a 15-year period that would be an incremental $77 million over and above the royalty-in-value price that we would be paying to the state." Finally, if the company were successful in exploration, one successful gas discovery would bring in $6.4 billion in "in-state value-add." He said that is shown in an economic study "that we have in our bid process." Number 1208 MR. SHARP, in the interests of time, indicated he would skip page 11, which shows how an explorer utilizes the [RIK] sale. MR. SHARP turned attention to pages 12 and 13, which relate to whether there is an impact to the producers. The "decision tree" on page 12 relates to whether to build in the RIK volume right from the start. It shows that at 4 bcf a day, if the pipeline is easily expanded, there is no impact to the producer group. If the RIK volume is built in right from the start, he emphasized, there is actually a significant benefit to the state, as well as - to his belief - to the producers. He explained, "Where they can accelerate production, you can have an incentive for more explorers and business and expenditures and jobs into the state, as well as it maximizes the gas price in Alaska, as the pipeline's not a bottleneck." MR. SHARP discussed the "cost side" for the producers [page 13] from the explorers' perspective. He noted that the chart shows the supply chain, including the process plant, the carbon dioxide (CO2) plant, and the pipeline. He offered the belief that the CO2 plant wouldn't be a bottleneck because its cost would be five to six times less than the pipeline; it wouldn't make sense for the producer group to underbuild that portion of the supply chain because they would want to keep the pipeline full. He referred to an example on the chart relating to downtime between the field and the pipeline; he said the end result is basically an impact of less than 5 cents per million cubic feet to the producers, which he believes to be "well within the accuracy of their forecasts of costs and prices for their project." He concluded, "From our perspective, it's insignificant impact to the producers." Number 1088 REPRESENTATIVE GUESS referred to page 12 and asked Mr. Sharp to go through the scenario of having 4.35 bcf a day and no exploration. She said it seems there would be a five-year contract, for example, and then [the explorers] might decide they didn't want to be in the business anymore; thus the gas going through the pipe might be down to 4 bcf a day. She suggested that in addition to the risk of not building a pipeline with enough capacity, there is quantifiable risk in building one bigger than will be used. She requested clarification about the ostensible lack of risk and the benefits of having extra capacity. Number 1009 MR. SHARP answered as follows: Right now in Prudhoe Bay they're cycling 6 to 8 bcf a day. And if you're only talking a 4-bcf-a-day pipeline or 4.35-bcf-a-day pipeline, really, you have the supply there. And so you could actually accelerate production from Prudhoe Bay and Point Thomson for that small portion of the pipeline; it only represents 8 percent of the capacity. And so you'd actually get accelerated gas sales. And on a time-value basis, that's significant value to both the state as well as the producer group. Number 0971 REPRESENTATIVE GUESS asked, "But isn't that forcing the people that are left over, that have the 4 bcf, into doing that?" MR. SHARP answered: Not necessarily. I think they would do it because it would maximize their revenue. But I think, more importantly, if you do have capacity on the pipeline, it creates an incentive for other people, other explorers, to come into the state and explore for gas as well. But I think that's really where you gain a competitive natural gas industry. The more players that you have, the more money that's spent in the state, the more jobs, the more revenue that's created. Number 0928 REPRESENTATIVE GUESS countered that it seems that the whole backstop proposal is just shifting risk. She explained: We'd either sell it to a producer such as yourselves and we're fine, or we force the people who own the pipeline to move it. So we're not really having any risk in either case. But ... you could leave after your contract and there still could be that empty capacity, or we could have ... 4 bcf and we could take the producers' view of "then they're forced to take it." MR. SHARP responded: I think there'd be two ways I'd add to that. I think first would be the gas potential on the North Slope. I think you have to take that viewpoint that out of a 100 [trillion-cubic-foot] potential, that if you have capacity on the pipeline and people are able to ... monetize their gas exploration and production, you're going to have lots of players out there exploring, because they're going to want to fill that piece of pipeline first before, let's say, the existing proven- reserve holders. And I think with that small margin of the 350 million cubic feet a day, I believe that could be easily filled by the existing proven reserves on the North Slope. And that's kind of why I had this next chart here [page 13], is that if you have a processing plant here with a capacity of 8 bcf a day, and you have the CO2 plant - which they have to put in place - what I'm suggesting is that you would overbuild this CO2 plant, regardless of whether you have the royalty-in-kind ... sale occurring, the reason being that this is only 20 cents, whereas the pipeline cost is five to six times as much. So you want to make sure you have excess capacity on the front end so you can always keep your highest-cost component of this supply chain full. So my argument ... is that the 350 million cubic feet a day is such a small portion of this overall volume, I believe it would be within the design of these facilities. In fact, ... if I was the producer, I would design that in, so I could keep my pipeline fully utilized .... Number 0764 MR. SHARP offered some of the conclusions outlined on page 14 of the handout. From an explorer's perspective, he noted, AEC believes the RIK is in the best interest of the state and that RIK provides no risk [to the state] or impact to the producer group, unless it is a positive impact due to the accelerated sales. In closing, he emphasized that AEC is offering to the state a vision of creating a competitive, multiplayer gas industry in Alaska, and believes that this RIK sale is the first step towards creating that. Number 0704 CHAIR OGAN thanked Mr. Sharp and requested that his company, along with other independents operating in Alaska, including Anadarko Petroleum Corporation, provide an overview to the committee as well as suggestions of what [the legislature] can do to make it easier for independents to do business in Alaska. He stressed timeliness in case legislation needs to be drafted. He then introduced Mark Hanley, former member of Alaska's House of Representatives. Number 0610 MARK HANLEY, Public Affairs Manager, Anadarko Petroleum Corporation, came forward to testify, noting that Mr. Sharp had gone over a lot of the issues already. He pointed out the following in the [the Anadarko/AEC] bid document: cash payments that have accrued [$350,000]; an exploration work commitment for $50 million to do exploration in the foothills looking for gas; a preference for in-state gas processing, which may encourage a company like Williams to process gas, for example; a preference for local hire; training obligations; and other items that he believes show that the state will get a value out of its royalty gas because of the addition of other factors beyond what the state would get otherwise. Clearly, if the state sells its royalty gas, he said, there is going to be added value from that. Number 0492 MR. HANLEY addressed timing. He emphasized that if the state doesn't sell its royalty gas before an open season, it is unlikely to get anything for its royalty gas. He told members: Everybody will bid capacity on the pipeline. It will be utilized at full capacity, and there'll be no reason for people that already have capacity to pay an extra premium to carry the state's gas. And anyone else that wants to buy the state's gas, other than potentially right on the North Slope, ... there won't be any capacity for them to take that down the pipeline. So they won't be able to bid. ... It is important, if the state is interested in getting extra value for its royalty gas, that that sale occur before any open season. And, again, you've heard the producers say they don't see one in this calendar year; of course, that could be early next year, which would have the same problems, or ... I suspect if they got their federal legislation and the tax credits that they were going [after] and their study finally finished up, and they said, "We've got a project," you would expect them to hold an open [season]. In fact, the state would encourage them to have an open season. ... The timing is crucial to have a royalty sale, to see what kind of bids you have out there. Number 0373 MR. HANLEY turned attention to whether FERC can force expansion and what its regulatory abilities are; he offered his belief that FERC is lax in how it regulates. He referred to a letter [dated January 15, 2002, from the Alaska Gas Producers Pipeline Team to DNR Commissioner Pat Pourchot] asking that the sale be canceled, noting that it suggests no precedent is cited in support of the assertion that FERC cannot compel expansion; it also says that FERC asserts it can compel pipeline expansion, and provides a citation. Mr. Hanley advised the committee that he could provide a legal citation that suggests FERC cannot. He recalled hearing Mr. Hurley say, however, that [FERC] could not force expansion, nor would that be desirable. Mr. Hanley said this is a critical issue for the committee to understand. He further said: You can't bid for initial capacity and take the risk if you don't have any gas. And if you don't bid for initial capacity, it's all going to go to the ... producers' team, and that's a natural. But what you really have is a policy call. If they control all the capacity - and we suggest if they control the initial capacity, it's going to make it almost impossible for anybody to get into the expanded capacity as well - you will not have exploration in this state, not by frontier explorers like Anadarko or Alberta Energy in areas like the foothills - at least not for many, many years, long after lease sales have expired. And, in fact, you're not likely to get additional participants at a future lease sale in the foothills if people cannot be guaranteed access. So there is an impact to the state. There's a benefit by selling the royalty gas. It's a guaranteed higher value. Number 0185 MR. HANLEY continued: The question you have is, the producers assert "this is going to kill the pipeline" or "it's unduly burdensome." That's your question, and you need to delve into that in detail, because we think there are ways that the potential risk that they suggest can be mitigated. One of the assumptions I think they made in their example, which is very simple, is that there's a 4-bcf pipeline. Well, do you build it and it's only 4 bcf? Can you not squeeze another molecule through? What is the level? ... Typically, even without expansion costs, there's some flexibility of 100, 200 mcf a day on a pipeline the size of 4 bcf. So, possibly, of the 300 that they say they would get, prorated, possibly 200 would be able to be absorbed within any system that they build. Of course, I think they may claim that they're going to build it to the absolute maximum molecule that can be put through, and not another. That's not, in our understanding, the reality of the situation. So, some of that risk is mitigated. Gas left in the field potentially means more oil recovery; that's [an] added value to the state and even, potentially, the producers; it mitigates some of that risk. So there are ways to go out there. I think one of the problems you have is it's very difficult to talk in theoretical terms when you don't know the specifics. And you don't know what they say the maximum volume's going to be. You don't know what they say the maximum pipeline capacity's going to be. We don't know what the expansion capacity [will be]. The terms and conditions of open seasons and expansion are generally set by those that build the pipeline. So of course they're going to set them both to their best economic value but also to their advantage for controlling the capacity, because that ... is an economic value to them as well. And so that's not a bad thing. They're going to do ... what's in the companies' best interest. It may not be in the state's best interest. It may not be in the explorers' best interest. MR. HANLEY said the question is whether explorers can be provided for; he cited ASRC as an example. TAPE 02-7, SIDE A Number 0001 MR. HANLEY reiterated the need to get specific information from the producers on how they will build this [pipeline]. He added that if the expansion capacity is also "one shot or nothing," it also has the ability to "freeze out" people; however, the producers could say it's the cheapest way to build it. He told the committee: You need to make that call, because ... if it goes forward the way it could very well go forward, you will have three producers, largely, controlling all the capacity, and you will not have exploration. And is that a good thing for the state? I think Conoco suggested awhile back that controlling capacity on a pipeline - and this was a common-carrier oil pipeline - was one of the reasons they left the state. ... You're hearing people tell you, "This is an issue; this could cause companies not to explore for things." Don't just take our word for it. Get your own independent evaluation of FERC authority and get the details from the producers so that you can actually make an honest value judgment of whether there is a risk, whether there are ways to mitigate that risk. Number 0139 REPRESENTATIVE GUESS asked Mr. Hanley whether he believes the RIK [gas sale] is the only way to ensure access and expansion of the gas line. MR. HANLEY answered, "Not necessarily." He said there are lots of public policy calls. For example, it could be a common carrier. The same issues would exist, he noted; the producers would argue that they don't want their gas prorated. He added: But it happens on oil lines all the time, and it's not unusual. It's unusual for a gas line, but this is an unusual gas line, with identified reserves that you know are out there to do it. You could reserve all the expansion capacity for new gas, or give it a preference. There are other ways to do things, absolutely. RIK is not the only way to go about this. Number 0231 REPRESENTATIVE DYSON remarked: We could also do something that guarantees there's always an open season, or that you guys don't get shut out of the open season because of your timing on exploration, or that, as [Mr. Sharp] suggested, that pipeline gets built with the excess-capacity potential and that you only have to pay your agreed-upon fair share of what expansion costs are, in order to get your gas in the pipe. MR. HANLEY replied: Possibly. ... But, again, it comes down to who controls the process .... If you start off with a goal of making sure it can be easily expanded and that's a policy you want to have, do you think you can design a project that can do that with minimal cost? Well, you probably can. It will have some extra cost, possibly, but is there some extra benefit even to yourself? Possibly, but these are things you don't know ... because you're not doing the design. And could you design a project that creates the most advantage for you ... on a business basis? Absolutely, making it difficult for others to get in. ... It can also be economic. Number 0369 CHAIR OGAN remarked that the more he deals with the pipeline issue, the more he realizes how little influence the state has on it; because of FERC, [most decisions come from] Washington, D.C. He thanked Mr. Hanley and invited to the witness table Mark Myers and Bonnie Robson of the Division of Oil and Gas. Number 0460 MARK MYERS, Director, Division of Oil and Gas, Department of Natural Resources, noted that online to answer questions was Kevin Banks, the division's commercial market analyst, who is the person within the division who has been most responsible for the RIK sale program. MR. MYERS commended the legislature and this committee for taking on this issue early; he emphasized the importance of this issue to the state. He pointed out that the process was begun the previous year when the legislature asked DNR to consider a potential sale to Netricity and to look at selling the state's RIK gas. He told members: We got the message loud and clear that the legislature wanted the state to look at the options it had for uses for its royalty gas and how it might sell that royalty gas versus leave it in value. So, again, we are ... trying to honor ... the commitment to you to fully evaluate it. An RIK sale does just that. We get proposals in from all parties ... interested in ... wanting to purchase RIK gas. So it was a very open process in the sense that ... anyone who could meet the minimum business requirements in the state ... could bid. Number 0550 MR. MYERS noted that the process has been characterized as an "RIK backstopping method." He stated: That's totally untrue; that's a total misconception. It is an open process, requires full analysis of all bids, regardless of what the intended purpose of those bids [is], and then it involves your legislative approval. So it's a very public process to look at all options for state ... RIK gas. And that's, again, part of what DNR considers. You've put a tremendous amount of fiduciary responsibility on us to manage our state oil and gas lands to the maximum benefit of the people of the state. And that's really what this is all about, is DNR's attempt to assure that we are maximizing value for the people of the state, whether it be financial value, whether it be in-state refining potential, local energy use by a local utility, or whether it be to allow for further exploration. And it's also, certainly, to receive maximum financial value ... for that gas received. Certainly, when you look at the way the proposal from the state was set up, it was designed to look at all those ... potentials. So I guess I take exception with the concept that the sale's purpose was to provide RIK backstopping. That was one of the possible uses that was listed, out of many other uses. So, hopefully we cleared up ... that misconception. Number 0665 MR. MYERS noted that this committee and others have been looking at what to do to facilitate a robust oil and gas industry in Alaska as oil revenues decline. He suggested rather than having incentive programs that give out dollars, the state should ensure fair access to its oil and gas lands, whether through lease sales or facilities. It is crucial to the process, he said. Number 0693 MR. MYERS referred to a handout titled "Alaska Royalty-In-Kind Gas Sale," dated February 5, 2002. He brought attention to Figure A, "Alaska's Onshore Basins," noting the potential beyond Prudhoe Bay and Point Thomson. If the state is to see that potential realized, he said, there has to be access. He likened it to building a superhighway and then not allowing anyone to travel on it; that is how critical access to the pipeline is to the state's future well-being, he told members. It applies not just to the North Slope foothills, but also to other Interior basins that might be along the pipeline's route. "It's not only intake of gas; it's also offtake of gas for local use," he said. "All those are critical issues that revolve around the issue of access to a pipeline." MR. MYERS turned attention to Figures B and C. He said the potential for gas on the North Slope is astounding. As mentioned by BP, for example, there is more than 100 trillion cubic feet of gas hydrates. He said those gas hydrates sit almost directly under the current existing facilities. Number 0770 MR. MYERS, in response to a question from Chair Ogan, explained that akin to ice, gas hydrates are actually frozen rather than being in a free, gaseous state. Gas hydrates contain a tremendous volume of captured gas. It is known that the hydrates are in the field because there have been extensive drilling through it and early studies. He added: We have all the well data, all the seismic data to indicate the hydrates are there, so we have great certainty; these numbers are certainty. Now, how much of that can be captured economically is another question. But ... we get into the issue of, will you overbuild this pipeline? And if you have another [trillion cubic feet] of gas sitting just underneath the existing infrastructure that won't be available for capacity in the line for 15 or 20 years ... or longer, I have great faith we'll find the technology to do it. [There are] research programs going on as we speak by the Department of Energy; there are two proposals that have been funded for Alaska by two different groups that ... will result in the drilling of wells to test the commercial production of these hydrates. Number 0863 CHAIR OGAN requested confirmation that the hydrates aren't currently in production. MR. MYERS said they are solid, at fairly shallow depths just underneath or in the base of the permafrost on the North Slope. He referred to Figure D, which shows a well cross-section displaying gas-hydrate and free-gas zones. He said, "We can quantify with great accuracy the amount ... of hydrates there." MR. MYERS brought attention to Figure E, "North Slope Gas Hydrate Potential." Although it shows hydrate potential all over the North Slope, he said, not just beneath the existing infrastructure, it is under the infrastructure that it would have the best economics. MR. MYERS told members the state wants to facilitate a long- term, viable gas industry. The question is how to get there. Obviously, there must be a pipeline, and "you can't burden it commercially to the extent that makes it unusable," he said. "However, we do believe that the RIK sale does not burden, yet could ... facilitate this process." MR. MYERS highlighted that this pipeline is contract carriage, whereas an oil pipeline is common carrier. Many of Representative Dyson's good questions on the issue of open access wouldn't be a question on a common-carrier line. However, a contract-carriage line doesn't provide the certainty that there is readily available access "to other folks." Number 0981 MR. MYERS told members: We've had numerous discussions with many consultants and external lawyers, FERC experts, and we've actually had internal communications within FERC. And FERC has never, to their internal knowledge, forced an expansion of a pipeline. They believe that market forces will, in fact, lead to the expansion. However, in Alaska we have a very unique situation. Those market forces in the Lower 48 would drive either the pipeline to expand or a new pipeline to be built if they weren't willing to expand. We're going to get one pipeline. MR. MYERS cited some reasons Alaska will get only one pipeline: environmental reasons, construction costs, lots of permitting, and treaty negotiations, for example. The same market-forces expectations aren't there as for a contract-carriage pipeline. He said: I think there's concern, and you've heard some of that concern by explorers. We have an RIK bid from a producer: Chevron, [which] has over 2 [trillion cubic feet] of gas on the Slope, has the same concerns. ... We have folks like Williams that are bidding that, again, are transporters, marketers; they have concern about access. And finally, we have local power companies and users concerned. So one of the things the RIK process brought out was we had bids from the total spectrum - from producers with known reserves to explorers to transporter-shippers and refiners ... and to the final end-users. Number 1047 MR. MYERS noted the enormity of this issue [of access]. After pointing out the differences of opinion, he said, "We are ... very uncomfortable that a contract-carriage pipeline will provide that access." He explained: Why is that access important in the sense of the state's RIK value ... and the timing issue? Well, the bottom line is, the state does not ship gas itself. The state has historically sold its gas on the North Slope, expecting whoever buys it to deliver that to market. ... They cannot do that if they don't have capacity in the pipeline, plain and simple. There has to be capacity ... for someone to buy RIK gas on the Slope unless they intend to use it on the Slope. Number 1101 CHAIR OGAN posed a scenario in which an entity that bids on the state's RIK ends up producing its own gas and putting it into [the pipeline], then substitutes the RIK gas. The producers would be required to carry the RIV gas, he suggested, and it would displace the throughput. He said that seems to be what the difference of opinion is about. He asked Mr. Myers to offer his view on that. He also invited the producers to come back before the committee to comment [at a later date]. Number 1183 MR. MYERS responded: Under that scenario, the state is a winner. That means additional gas has been discovered and is being produced on the North Slope. So new gas reserves are coming online for the state, with ... the billions of dollars of added value that goes along with it. So we are a winner. ... That means there's additional capacity in the pipeline system. ... That implies, then, that the pipeline is operating at a higher production level and ... is more efficient. Producers - I think the issue steps back to a larger issue of, is a pipeline a pipeline, or is a pipeline an extension of the existing oil fields? Now, clearly a pipeline's supposed to be a separate infrastructure ... from the oil fields. It's regulated separately; it's a very different beast. I do not see any of those cases where the pipeline itself is disadvantaged in this case. ... The pipeline economics are always positive; in fact, they're better there, and they're better in this case. What would then happen, if the producers feel that they were getting less [throughput] of their gas, they would then ask for an expansion of the capacity of the pipeline; the pipeline would expand - the pipeline has more rates, has better economics in that case. So, again, the pipeline wins, we win, the producers ultimately win, but there's a period of time prior to that expansion where they would then have to forego some of their gas in order to carry RIV gas. ... So basically we see, again, if you look at the analysis by Alberta Energy, we see an effect on the producers' cash flow. That effect is relatively minimal for the value to the state and to other folks, and, again, we believe there are ways to totally mitigate that loss and damage. Number 1339 REPRESENTATIVE FATE inquired about the endpoint where expansion ceases and it becomes uneconomical and inefficient to continue that expansion. Given the tremendous amount of potential up there, and given that the market price of gas is expected to be economic when this comes online, he said, there may be a huge surge that will "go above that endpoint." He asked: What do we do then? MR. MYERS said that is a very good question. He answered: Basically, if you look at the design [specifications] of the proposed pipelines, they have generally .8 to 1 bcf of additional expansion capacity planned. And that ... expansion capacity depends on the pressure of the line and ... a little bit on the gas itself, but then on the amount of compression. ... The economic part of the expansion curve is designed into the pipeline in the early stages, but what the producers are suggesting is ... about .8 to 1 bcf of expansion capacity. Then it gets very expensive and very inefficient, and you have to basically double the pipeline - create another parallel pipeline or make large loops in the pipeline - to get expansion capacity beyond that, when probably that is going to be very marginally ... challenged economically to do that. So approximately 20-25 percent expansion capacity is probably going to be the limit, [given] design specs at this time. So what do you do after that? You wait in line. And if you don't have expansion capacity, nothing happens. You wait till there is capacity in the line. Most gas pipelines are built with expansion capacity. In other words, they're built at less than the known offtake. So this is a very unusual case, where we have the ... capability to offtake at least 8 bcf and no design has contemplated anywhere near that size. The current reserve base is probably problematic for that level of offtake as well. So the bottom line is, this is a unique situation where the pipeline, as you have suggested, is constrained not by the ... ability to deliver supply, but by the size of the pipe. ... We can't do much about that; that's an engineering-spec problem and a cost differential that will make expansion beyond about 25 percent probably uneconomic. Number 1470 CHAIR OGAN asked whether Mr. Myers was saying design is the limiting factor because "we've got as much gas as we can put down the line." If that is the case, he asked, how much does the "offtake affecting production" drive that decision? He offered his understanding that studies were planned but not done by the AOGCC. He asked how much [the division] is looking at it as well. CHAIR OGAN said he'd like to see some independent analysis regarding how that affects oil production. He noted that a warm winter on the North Slope results in a drop in production because not as much gas is being injected; he suggested that certainly offtake would affect it. Also in the mix is the amount of gas being produced in the foothills, for example; he said the more gas is produced in the foothills, the less gas will be taken off the existing producing oil fields, and the longer those fields will last. Number 1562 MR. MYERS responded: First of all, there are ongoing studies to look at offtake rates. It's a little more complicated that just Prudhoe Bay because Point Thomson contains at least 8 bcf of gas reserves as well. So you have a balance between two fields, and ... since Point Thomson will be ... a green field, a brand-new production facility, there's a lot of latitude to design what that level of offtake is and what you do to optimize the liquids recovery as well. Prudhoe Bay, the same way, there are mitigation measures such as the "pressure-support initiative" where you inject water into the gas cap. There are ways to mitigate the offtake of gas. And then the timing of initial sale of the pipeline has great effect. ... You see the rapid decline in Prudhoe is continuing on the main reservoir. So if the gas sale is delayed a few years, the question is very different in terms of oil loss than if it comes on in, say, a 2008 timeframe. 2008 versus 2010 - [they] are different. All those are [mitigable] standards, and certainly everyone has to look at the economics of ... oil loss, the conservation of the resource involved with that. But there is a tremendous amount of flexibility in that process. And, again, if you think about the 2008 timeframe, an explorer would have time in that timeframe to go out there. ... They've got six years. They've got two or three years to delineate additional gas reserves as well to, again, ... look at other gas coming ... into the system. But, again, you can't ... nominate gas unless you have it because the risk you take is ... substantial. ... I believe there's a workable solution. ... It's partially economics, partially drawn by the reservoir engineering. But it's a [mitigable] standard because of the flexibility to take ... offtake gas from both Prudhoe and Point Thomson. And it's also driven, then, by market value of gas ... versus incremental oil recovery. Number 1673 CHAIR OGAN stated his understanding, then, that the issue of the oil production's not being as prolific isn't really a driver in the decision of how much gas is put in the line or the ultimate decision on how big to build it. MR. MYERS responded that there is a range of values; within the range of values for a probable pipeline, however, there are "solid ways" to mitigate the oil loss. He added: Now, if you're talking about taking 6 bcf out of Prudhoe Bay, no, there's not; there would be significant oil loss. If you're talking about 2.5 to 3 and the rest out of Point Thomson, it's a much easier issue to deal with. ... Within the sidebars of the potential sizes of a pipeline between 4 and, say, ... 5.5 or so, those are totally [mitigable]. But if you get a very large number like 6 and 8, then the issue becomes very acute and ... there's going to be more oil loss. Number 1730 CHAIR OGAN suggested that gas from the foothills would play some role in extending the oil fields. He asked whether that is a fair assumption. MR. MYERS answered: If you were to produce gas from other resources, definitely the oil loss would be less. Ultimately, there will be some oil loss. The ... longer you maintain higher reservoir pressures in the field, the longer you maintain miscible flood injection, miscible flood, the more oil you're going to recover. But that ... window of oil you recover becomes smaller and smaller and smaller as time goes out. Number 1770 BONNIE ROBSON, Deputy Director, Division of Oil and Gas, referred to Chair Ogan's mention of testimony from BP and Phillips that the RIK sale may harm the pipeline project or harm them as producers. She said: I think both the statements of Mr. Hurley and Mr. Konrad were to the effect that "we do not object to all RIK sales; we only object to those sales where some volume of gas may be ... taken out of royalty in kind and put back to the producers as royalty in value during the period of time required as a commitment for pipeline capacity." And he gave an example where there could be a possible put-back of .3 bcf of gas from an RIK purchaser to the "big three" during the period, say, a 15-year commitment for the initial pipeline capacity. There's a couple of points I think need to be made in response. First of all, if .3 [bcf is] put back to BP, Exxon, and Phillips, they have come forth and stated that this pipeline ... can be expanded relatively easily and fairly through an open process with FERC. And if they have an additional .3 [bcf] at that time that they need to get to market, then they can seek expansion of the pipeline at that point in time. And I suggest to you that it will be easier for those who own the pipeline to expand the pipeline than for those who do not own the pipeline and have no standing to compel expansion. Number 1863 MS. ROBSON continued: The second point to keep in mind in this regard is that what they are essentially saying when they say that they do not object to all RIK sales, just one where the duration of deliveries may be less than the pipeline commitment - and I'll use 15 years as an example of a pipeline commitment - ... is, "We recognize that while the lease form gives the state the right to switch between royalty in value on six months' notice, we, in fact, want that six months to be changed to 15 years." They are asking for a change in the term of the leases that they execute with the state. And I think, in deciding whether or not that's an appropriate change to ratify, you need to look at the standards that the statutes - in fact, this legislature - have dictated for providing some form of royalty relief. Basically, the leases have two provisions on royalty. The first imposes royalty and sets the rate - typically at 12.5 percent. The second gives the state the right to take its royalty in kind or in value, and to switch on six months' notice. Now, you have dictated that when they want relief from the imposition of royalty, from the 12.5 percent rate -- let's say they want to go to 10 percent. What they must do, to do that, is to come to bare their soul, to show their economics, to open their books, to convince you that royalty relief is needed, is in fact justified, and will not harm the state - in fact, will benefit the state. Here, they are asking for a form of royalty relief. They are saying, "We do not like the six-months'- notice provision in the lease forms. We want that to read 15 years." I suggest to you that it is appropriate for them to come forth and to provide the numbers, provide the economics, to open their books, to show that it really does hurt, and that there is not an alternative. We have, in fact, asked the producers to come forth and to make that showing, to run us the numbers. Today is the first day we have seen any numbers. We will explore them further. We will continue to ask the producers. We will examine whatever numbers they provide .... We have attempted to run the numbers ourselves in the absence of their information, and we do not reach the same conclusions. We see the possibility that this could, in fact, have a net economic advantage to them, and certainly to the state in many arenas. So I think you need to keep that in mind, and we need to ask the producers the hard questions, to make them show us the numbers that would justify a conclusion that this sale could, in fact, harm them and harm the project. Number 2019 MR. MYERS offered further comments: The other question is - and I think Representative Dyson was trying to get at the issue - are there other ways to assure access? And we have explored with the producers, with ... two of them, at least - Phillips and BP - on whether or not they'd be willing to write up language that would assure other folks - including ourselves but including "explorationists" and other people that might want access to gas - that ... there would be reasonable expansion potential and fair access to that expansion capacity. They have declined to provide that language. The response was a protest to the RIK sale. They've also told us that -- Phillips has sent us a letter saying the terms of the RIK sale are commercially unreasonable, which is their term. Yet you've seen the bids ... that support, from a wide variety of users, from ... a producer with significant reserves on the slope that has concern about access to explorers that have concern about access, to, again, a pipeline marketing company, to an end-user, all of which felt the need to bid and did not see the terms as commercially unreasonable. So, again, there's ... strong differences of opinion, and I'd commend you if you would explore as to why these differences exist. Number 2094 CHAIR OGAN replied that he would like to do that. He announced that he would recess the meeting until Thursday at 10 a.m. in order to continue the discussion and allow the producers an opportunity to respond. He advised members that he would assign a subcommittee at that time in order to facilitate discussion and try to resolve the differences. He agreed it is an important issue and expressed appreciation for testifiers' participation. ADJOURNMENT  CHAIR OGAN recessed the House Special Committee on Oil and Gas meeting at 12:17 p.m., with the meeting to be continued on Thursday, February 7, at 10 a.m.